The present invention relates to a method for reducing pollutant gas levels in flue gases generated in catalyst regenerators in hydrocarbon catalytic cracking systems.
Modern hydrocarbon catalytic cracking systems use a moving bed or fluidized bed of a particulate catalyst. Catalytic cracking is carried out in the absence of externally supplied molecular hydrogen, and is thereby distinguished from hydrocracking, in which hydrogen is added. In catalytic cracking, catalyst is subjected to a continuous cyclic cracking reaction and catalyst regeneration procedure. In a fluidized catalytic cracking (FCC) system, a stream of hydrocarbon feed is contacted with fluidized catalyst particles in a hydrocarbon cracking zone, or reactor, usually at a temperature of about 427.degree.-600.degree. C. The reactions of hydrocarbons in the hydrocarbon stream at this temperature result in deposition of carbonaceous coke on the catalyst particles. The resulting fluid products are thereafter separated from the coked catalyst and are withdrawn from the cracking zone. The coked catalyst is stripped of volatiles, usually with steam, and is cycled to a catalyst regeneration zone. In the catalyst regenerator, the coked catalyst is contacted with a gas, such as air, which contains a predetermined concentration of molecular oxygen to burn off a desired portion of the coke from the catalyst and simultaneously to heat the catalyst to a high temperature desired when the catalyst is again contacted with the hydrocarbon stream in the cracking zone. After regeneration, the catalyst is cycled to the cracking zone, where it is used to vaporize the hydrocarbons and to catalyze hydrocarbon cracking. The flue gas formed by combustion of coke in the catalyst regenerator is removed from the regenerator. It may be treated to remove particulates and carbon monoxide from it, after which it is normally passed into the atmosphere. Concern with the emission of pollutants in flue gas, such as sulfur oxides, has resulted in a search for improved methods for controlling such pollutants.
The amount of conversion obtained in an FCC cracking operation is the volume percent of fresh hydrocarbon feed changed to gasoline and lighter products during the conversion step. The end boiling point of gasoline for the purpose of determining conversion is conventionally defined as 221.degree. C. Conversion is often used as a measure of the severity of a commercial FCC operation. At a given set of operating conditions, a more active catalyst gives a greater conversion than does a less active catalyst. The ability to provide higher conversion in a given FCC unit is desirable in that it allows the FCC unit to be operated in a more flexible manner. Feed throughput in the unit can be increased, or alternatively a higher degree of conversion can be maintained with a constant feed throughput rate. The type of conversion, i.e., selectivity, is also important in that poor selectivity results in less naphtha, the desired cracked product, and higher gas and coke makes.
The hydrocarbon feeds processed in commercial FCC units normally contain sulfur, usually termed "feed sulfur". It has been found that about 2-10% or more of the feed sulfur in a hydrocarbon feedstream processed in an FCC system is invariably transferred from the feed to the catalyst particles as a part of the coke formed on the catalyst particles during cracking. The sulfur deposited on the catalyst, herein termed "coke sulfur", is passed from the cracking zone on the coked catalyst into the catalyst regenerator. About 2-10% or more of the feed sulfur is continuously passed from the cracking zone into the catalyst regeneration zone in the coked catalyst. In an FCC catalyst regenerator, sulfur contained in the coke is burned along with the coke carbon and hydrogen, forming gaseous sulfur dioxide and sulfur trioxide, which are conventionally removed from the regenerator in the flue gas.
Most of the feed sulfur does not become coke sulfur in the cracking reactor. Instead, it is converted either to normally gaseous sulfur compounds such as hydrogen sulfide and carbon oxysulfide, or to normally liquid organic sulfur compounds. All these sulfur compounds are carried along with the vapor cracked hydrocarbon products recovered from the cracking reactor. About 90% or more of the feed sulfur is continuously removed from the cracking reactor in the stream of processed, cracked hydrocarbons, with about 40-60% of this sulfur being in the form of hydrogen sulfide. Provisions are conventionally made to recover hydrogen sulfide from the effluent from the cracking reactor. Typically, a very-low-molecular-weight off-gas vapor stream is separated from the C.sub.3 + liquid hydrocarbons in a gas recovery unit, and the off-gas is treated, as by scrubbing it with an amine solution, to remove the hydrogen sulfide. Removal of sulfur compounds such as hydrogen sulfide from the fluid effluent from an FCC cracking reactor, e.g., by amine scrubbing, is relatively simple and inexpensive, relative to removal of sulfur oxides from an FCC regenerator flue gas by conventional methods. Moreover, if all the sulfur which must be removed from streams in an FCC operation could be recovered in a single operation performed on the reactor off-gas, the use of plural sulfur recovery operations in an FCC unit could be obviated, reducing expense.
It has been suggested to diminish the amount of sulfur oxides in FCC regenerator flue gas by desulfurizing a hydrocarbon feed in a separate desulfurization unit prior to cracking or to desulfurize the regenerator flue gas itself, by a conventional flue gas desulfurization procedure, after its removal from the FCC regenerator. Clearly, either of the foregoing alternatives requires an elaborate, extraneous processing operation and entails large capital and utilities expenses.
If sulfur normally removed from the FCC unit as sulfur oxides in the regenerator flue gas is instead removed from the cracking reactor as hydrogen sulfide along with the processed cracked hydrocarbons, the sulfur thus shifted from the regenerator flue gas to the reactor effluent constitutes simply a small increment to the large amount of hydrogen sulfide and organic sulfur invariably present in the reactor effluent. The small added expense, if any, of removing even as much as 5-15% more hydrogen sulfide from an FCC reactor off-gas by available means is substantially less than the expense of reducing the flue gas sulfur oxides level by separate feed desulfurization. Present commercial facilities for removing hydrogen sulfide from reactor off-gas can, in most if not all cases, handle any additional hydrogen sulfide which would be added to the off-gas if the sulfur normally discharged in the regenerator flue gas were substantially all shifted to form hydrogen sulfide in the FCC reactor off-gas. It is accordingly desirable to direct substantially all feed sulfur into the fluid cracked products removal pathway from the cracking reactor and thereby reduce the amount of sulfur oxides in the regenerator flue gas.
It has been suggested, e.g., in U.S. Pat. No. 3,699,037, to reduce the amount of sulfur oxides in FCC regenerator flue gas by adding particles of Group IIA metal oxides and/or carbonates, such as dolomite, MgO or CaCO.sub.3, to the circulating catalyst in an FCC unit. The Group IIA metals react with sulfur oxides in the flue gas to form solid sulfur-containing compounds. The Group IIA metal oxides lack physical strength. Regardless of the size of the particles introduced, they are rapidly reduced to fines by attrition and rapidly pass out of the FCC unit with the catalyst fines. Thus, addition of dolomite and the like Group IIA materials is essentially a once-through process, and relatively large amounts of material must be continuously added in order to reduce the level of flue gas sulfur oxides.
It has also been suggested, e.g., in U.S. Pat. No. 3,835,031, to reduce the amount of sulfur oxides in an FCC regenerator flue gas by impregnating a Group IIA metal oxide onto a conventional silica-alumina cracking catalyst. The attrition problem encountered when using unsupported Group IIA metals is thereby reduced. However, it has been found that Group IIA metal oxides, such as magnesia, when used as a component of cracking catalysts, having a rather pronounced undesirable effect on the activity and selectivity of the cracking catalysts. The addition of a Group IIA metal to a cracking catalyst results in two particularly noticeable adverse consequences relative to the results obtained in cracking without the presence of the Group IIA metals: (1) the yield of the liquid hydrocarbon fraction is substantially reduced, typically by greater than 1 volume percent of the feed volume; and (2) the octane rating of the gasoline or naphtha fraction (24.degree.-221.degree. C. boiling range) is substantially reduced. Both of the above-noted adverse consequences are seriously detrimental to the economic viability of an FCC cracking operation, so that even complete removal of sulfur oxides from regenerator flue gas would not normally compensate for the simultaneous losses in yield and octane which result from adding Group IIA metals to an FCC catalyst.
Alumina has been a component of many FCC and moving-bed cracking catalysts, but normally in intimate chemical combination with at least 40 weight percent silica. Alumina itself has low acidity and has generally been considered to be undesirable for use as a cracking catalyst. The art taught that alumina is not selective, i.e., the cracked hydrocarbon products recovered from an FCC or other cracking unit using an alumina catalyst would not be desired valuable products, but would include, for example, relatively large amounts of C.sub.2 and lighter hydrocarbon gases.
U.S. Pat. No. 4,071,436 discloses the use of alumina for reducing the amount of sulfur oxides in the flue gas formed during cracking catalyst regeneration. The alumina can be used in the form of a particulate solid mixed with cracking catalyst particles. In some cases, alumina contained in the cracking catalyst particles is also suitable; however, alumina contained in conventional cracking catalysts is usually not very active, since it is intimately mixed with a large fraction of silica.
U.S. Pat. Nos. 4,115,250 and 4,115,251 disclose the synergistic use of oxidation-promoting metals for carbon monoxide burning in combination with the use of alumina for reducing the amount of sulfur oxides in cracking catalyst regenerator flue gas. When alumina and highly active oxidation-promoting metals are both included in the same particle, alumina in the particle is ineffective for removing sulfur oxides from the regenerator flue gas, especially in the presence of even a small amount of carbon monoxide. On the other hand, when the alumina and combustion-promoting metal are used on separate particles circulated together in a cracking system in physical admixture, the ability of the alumina to reduce the level of sulfur oxides in the flue gas can be considerably enhanced.
In reducing the level of sulfur oxides in catalyst regenerator flue gas using alumina, as disclosed in U.S. Pat. Nos. 4,017,436, 4,115,250 and 4,115,251, in a catalytic cracking system under commercial operating conditions it has now been noted that silicon and silicon compounds, especially silica, in the particulate catalyst used in a catalytic cracking system, can exert an unexpected detrimental effect on the activity and stability of alumina contained in particles other than the catalyst particles in the particulate inventory, with respect to the capacity and rate of reaction of the alumina in forming sulfur-containing solids in a catalyst regenerator. Silicon contained in zeolitic crystalline aluminosilicates apparently does not migrate to any substantial extent, and therefore does not cause alumina deactivation. Previously, it was known that contamination of alumina by silica presented a problem when the silica was chemically combined with alumina prior to introduction into the circulating particulate solids inventory, or, more generally, when the silica was already present in the same particles as the alumina. It has now been found that under the conditions found in commercial catalytic cracking and regeneration systems, silica can migrate from particles of higher silica concentration to particles of lower or zero silica concentration during circulation of a mixture of such particles in a cracking system. Silica which is subject to such migration may be termed "amorphous" or "non-crystalline" silica, to distinguish it from silica in the form of zeolite crystalline aluminosilicates, which is relatively stable and is subject to little or no migration between particles under commercial FCC operating conditions. It is believed that the silicon is carried between particles in the hot gases, such as steam, which are present in catalytic cracking systems. The present invention is directed, in part, to overcoming the problem of deactivation of alumina resulting from silica migration from high-silica-content particles to alumina-containing particles in the particulate solids inventory in a catalytic cracking system.